Monday, June 30, 2014

Saudi Aramco cuts July propane to $820/T, down $15 from the June Level

State-run Saudi Aramco has cut its July contract price for propane to $820 a tonne, down $15 from the June level, an industry source said on Monday. Butane prices for July 2014 were set to $840 a tonne, up $5 from June level of $835. The prices provide a benchmark against which Middle East sales of liquefied petroleum gas (LPG) to Asia are priced. Following is a table of Saudi Aramco's contract prices of propane and butane per tonne in U.S. dollars. 

Product   July  2014  -   June 2014     Change 

Propane  $820                $835                -15
Butane     $840               $835                +5


Saudi Arabia February CP Price

The key energy commodity price trends of U.S. in 2013
Japan Energy Report
Saudi Arabia Energy Report
India Energy Report

Thursday, June 26, 2014

Europe Gas Storage Seen Enough for Ukraine Supply Cut

With just over 100 days until the start of the new winter gas season, and despite uncertainty over how the ongoing Moscow-Kiev gas dispute will affect European imports of Russian gas transiting Ukraine, the rate of gas injections in the key storage region of Germany remains little changed since the start of summer.

According to data from Gas Infrastructure Europe, German storage was 75.52% full Thursday, with 16.4 billion cubic meters of gas in stock.Since April 1, regarded as the first day of summer gas season, Germany has been injecting gas into storage at a rate of 30 million cubic meters/day at its weakest and at 83 million cu m/d at its strongest, with the average daily rate standing at just under 55 million cu m.In the past month, the rate has stood at 57 million cu m/d.

Were Germany to carry on injecting gas into storage at a rate around 55 million cu m/d, German gas stocks should be full by the second half of September, before the October 1 start of winter, with about 5.3 Bcm required to be injected before reaching full capacity.With that same rate, German storage should be 90% full by August 15.Withdrawals have been relatively limited, totalling 272 million cu m since April 1 and averaging 3.4 million cu m/d.

These stable rates indicate there has been no pressure for storage facilities in Germany to inject at a faster rate on the back of the Ukraine crisis, with Europe's markets continuing to be well supplied with gas despite Russia cutting off supplies to Ukraine at the start of the week.Furthermore, Germany receives gas from Russia not only through the Ukraine-Slovakia-Czech Republic route, but also directly from Russia via the subsea Nord Stream pipeline and via Yamal, a pipeline traversing Belarus and Poland.

Morning nominations showed that Germany would receive 101 million cu m/d of Russian gas on Friday via Nord Stream and 84 million cu m/d via Yamal.On August 15 and October 1 German storage was 68.34% and 82.96% full respectively during 2013, GIE data showed. However, a mild October allowed Germany to carry out robust injections into November, and by November 3 German storage was 91.46%, before withdrawals began to outnumber injections.

As a result of a mild 2013-14 winter, German storage was 58.35% full by the March 31, 2014 end of the season, compared with 21.52% full a year before.

Ukrainian and EU experts on Wednesday, June 25, began exploring possibilities for reverse-flow gas supplies to Ukraine, EU Energy Commissioner Gunther Oettinger said after talks with Ukrainian Energy and Coal Industry Minister Yuriy Prodan.

Prodan said Ukraine could become independent from Russian gas “if Slovakia begins large-scale reverse-flow supplies” and added that closely linked to this issue was “the pumping of gas into underground storage facilities is closely linked”.He said the sides had agreed to continue bilateral talks next week on an open and transparent basis.“Everything will depend on how much reverse-flow gas we can buy from Europe. We have been getting some very good offers from European companies at prices that are much better than those of Gazprom, even after discounts,” he said.

“We hope we will be able to begin ‘minor’ Slovak transit from October 1 even though some technical issues remain to be worked out,” Prodan said.

As for the “big” revere-flow supplies, he said “the gas transportation network in the direction of Slovakia is working at only 40% of its capacity. So there is a possibility.”Oettinger confirmed that the European Union was committed to reverse-flow gas supplies to Ukraine but this gas would be sold at market prices to be determined by the companies that sign relevant contracts.

Prodan said he was hopeful that “big reverse-flow supplies” would give Ukraine “up to 30 billion cubic meters a year”.Oettinger’s spokesperson Sabine Berger said Ukraine could count on no more than 8 billion cubic meters of reverse-flow gas a year through Slovakia a part of the “minor reverse-flow scheme”. Gas will be supplied by the Vojany-Uzhgorod pipeline, not the transit pipeline.

As for the “big reverse-flow supplies” there is no concrete agreement yet as it would require Slovakia to agree to reverse the flow of gas by a trunk pipeline, which it is not prepared to do because this would run counter to its contract with Gazprom.

Oettinger said reverse-flow gas supplies from Slovakia to Ukraine by the trunk pipeline would be impossible without Gazprom’s consent as it would run counter to the Slovak company Eustream’s contractual obligations.However he said such supplies by the Vojany-Uzhgorod pipeline would not require the Russian company’s agreement and would give Ukraine up to 10 billion cubic meters of a gas a year.

Oettinger believes that diversification of supplies will help to solve Ukraine’s gas problem in part. However reverse-flow supplies from Poland and Hungary by the Vojany-Uzhgorod pipeline will not be enough for Ukraine get through the coming winter comfortably.The European Union has promised assistance to Ukraine in diversifying natural gas supplies.Kiev is planning to buy about 290 million cubic meters of gas in Europe in reverse mode (about 140 million cubic meters will be delivered through Poland and the rest through Hungary).

Ukraine has been receiving natural in reverse flows from Europe since November 1, 2012. The gas is supplied across the Ukrainian border with Poland under a contract with from German RWE.The gas is supplied across the Ukrainian border with Poland. RWE planned to supply up to 5 billion cubic metres of gas to Ukraine until May 2013. Last year, Naftogaz imported 55 million cubic meters of gas using the reverse flow scheme.

Gazprom said it might impose restrictions on European companies which supply gas to Ukraine using reverse-flow mechanisms.“A reverse flow is a semi-fraudulent mechanism whereby gas runs in circles. But this is Russian gas,” Gazprom CEO Alexei Miller said.Miller said that the points where gas was delivered to and accepted by European consumers were located in Europe, but “Ukraine uses our gas [intended for Europe] on its territory any way it likes”.

“Reverse-flow gas supplies run counter to the contracts with European companies that buy Russian gas, and for that reason restrictions may be imposed on them,” Miller said.In 2013, Ukraine consumed about 50 billion cubic meters of gas.

Natural gas for winter delivery in the U.K. declined to the lowest level in more than three years amid high inventories, tanker arrivals and a reduced risk of interruptions in Russian gas supplies via Ukraine.

The contract for the six months from October fell as much as 1.2 percent to the lowest level for a next-winter contract since January 2011, according to broker data compiled by Bloomberg. A strengthening pound also led utilities in mainland Europe to favor buying under long-term contracts rather than on hubs such as the U.K.’s National Balancing Point, said Nick Campbell, an analyst at Inspired Energy Plc in Kirkham, England.

Europe’s mildest winter in seven years depleted demand and meant less gas was needed to replenish storage sites, which are currently 25 percentage points above last year’s, according to Gas Infrastructure Europe, a lobby group in Brussels. The winter contract has fallen 4.9 percent since June 16, the day Russia cut deliveries to Ukraine, as onward flows to Europe remained near normal levels, reducing fears of possible interruptions like those seen in 2006 and 2009.

“The continued rapid build in inventories is one of the main factors” damping winter prices, Ole Hansen, head of commodity strategy at Saxo Bank A/S in Copenhagen, said by e-mail. “It’s a reaction to the continued drop in spot gas and the fact that European gas inventories continue to build at a faster rate than anytime during the past five years.”

Winter gas declined as low as 57.8 pence a therm ($9.85 per million British thermal units) and traded at 58.1 pence a therm at 4:13 p.m. in London, broker data show. Same-day gas fell as much as 4.6 percent to 37.5 pence a therm as flows outpaced demand.

European storage sites were 68 percent full yesterday, the highest for this time of year since 2011. Gas deliveries at the border with Ukraine, which meets about 15 percent of Europe’s gas needs via pipelines from Russia, are proceeding as normal, according to Slovakia’s pipeline operator Eustream.

The reduced Ukraine risk “along with storage fullness, plentiful LNG and the strong sterling has led to European utilities favoring long-term gas rather than buying from the U.K., thus seeing more sellers than buyers of the seasonal contract” Campbell said by e-mail today.

The pound approached the highest since October 2012 versus the euro as the Bank of England’s Financial Policy Committee introduced measures to cool the housing market. Sterling strengthened 0.3 percent to 79.98 pence per euro after climbing to 79.59 on June 16, the highest level since Oct. 1, 2012.

Prices also weakened as Brent crude oil traded near its lowest closing level in a week after Iraq said oil exports from the south of country will still increase amid the northern insurgency. Futures fell 0.5 percent to $113.38 a barrel on the ICE Futures Europe exchange.

Wednesday, June 25, 2014

California set new record for solar electricity production

Average hourly California renewable electricity production

On June 1, 2014, the California Independent System Operator (CAISO) recorded a record midday hourly peak of 4,767 megawatts of alternating current (MWAC) of utility-generated solar electricity delivered into the California grid. With rapidly growing utility-scale solar capacity, CAISO has regularly recorded new hourly output records going back to 2010 when it first began publishing the daily data. When the hourly data are averaged over the course of a month to control for weather variation, the average peak hourly generation in May 2014 of 4,086 MWAC was 150% greater than the level in May 2013.

In 2013, 2,145 MW of utility-scale solar capacity entered service in California, of which more than 500 MW came from large-scale solar thermal plants. California accounted for more than 75% of U.S. utility-scale solar capacity installed in 2013.

Total solar electricity output in May 2014 constituted 6% of the total CAISO electricity load that month, compared with 2% in May 2013. However, during the average peak solar output hour, between 11:00 a.m. and noon for May 2014, solar supplied 14% of total power, compared with 6% in May 2013.

Solar generation facilities generally provide power to the CAISO grid from early morning until the evening, and reach peak output around midday. When solar electricity is being generated, less electricity from other sources such as natural gas or interstate electricity imports is required. Conversely, when there is little-to-no solar generation, the shares of other fuels used in California's supply mix rise.

Average hourly California solar electricity production by month
Average hourly California renewable electricity production by month
Average hourly California  electricity production for all sources by month

While solar generation follows a relatively consistent pattern throughout the day (see above pic1), CAISO also faces challenges in integrating other renewables (see above pic2). Wind output during the summer months frequently coincides with the afternoon and evening peak demand hours, but it is also an intermittent resource and therefore has a limited ability to provide firm capacity. Hydroelectric power, which provides 12% of California's net generation, is typically a flexible, dispatchable resource—but is also subject to seasonal variability, drought effects, and restrictions on dispatch created by the needs of other water users.

AC/DC Measurement of Solar

EIA collects electric capacity data in alternating-current megawatts (MWAC), the type of electricity used in homes and on the grid. Solar photovoltaic generators produce electricity in direct-current megawatts (MWDC), which is how organizations like the Solar Energy Industries Association report capacity. Generally, PV systems are associated with an AC-to-DC ratio between 80% and 90%.

Solar and renewables still constitute a relatively small share of generation for California in the context of all fuel sources (see above pic3). Natural gas accounted for 59% of net generation in 2013, and 3,940 MW of new natural gas capacity came online in 2013, which will help address some of the reserve capacity needs for balancing renewables, as well as replace some of the baseload power that was lost when two of the state's four nuclear units were retired in 2012.

California's utilities are less than two-thirds of the way toward meeting their 2020 RPS goals. With declining solar manufacturing costs, and the federal investment tax creditin place through the end of 2016, utility-scale solar installations are expected to continue through 2014. Projects currently reporting to EIA have indicated plans for an additional 1,728 MWAC of new utility-scale solar to be installed between May and December 2014.

In addition to leading the nation in utility-scale solar capacity, California also has a significant level of behind-the-meter residential and commercial solar photovoltaic (PV) capacity. According to the Solar Energy Industries Association, approximately 700 MWDC of residential and commercial/industrial solar PV capacity was also installed in California in 2013, further reducing midday baseload power demand.

Tuesday, June 24, 2014

The NYMEX July natural gas futures contract settled 11,2 cents lower

The NYMEX July natural gas futures contract fell at $4.446/MMBtu on Tuesday as the market rallied on some bargain hunting after several straight sessions of decline, analysts said.

The contract lost 34.3 cents in value over the previous week.

nymex natural gas future 2013-2014

"I think the selloff yesterday was a little overdone, so we're seeing some bargain hunting [as a result of] heat in the back-end of the forecast" IAF Advisors analyst Kyle Cooper said. "It sounds kind of boring. The market seems to be trapped in a $4.60-$4.80 range."

"We had a solid seven trading days that were down or flat, so we're seeing a little bit of balancing here," said David Thompson, executive vice president at PowerHouse.

Phil Flynn, senior market analyst at Price Futures Group, said the larger market did get some upbeat economic data Tuesday on consumer confidence, and the gas contract increase was likely some "short-covering."

The July contract traded between $4.431/MMBtu and $4.556/MMBtu Tuesday.

The NYMEX settlement is considered preliminary and subject to change until a final settlement price is posted at 7 pm EDT (2300 GMT).

Monday, June 23, 2014

The U.S. faces a natural gas shortfall this year

On June 13, a net natural gas storage injection of 113 billion cubic feet (Bcf) brought natural gas working inventories in the contiguous United States to 1,709 Bcf. Strong injections over the past six weeks raised storage levels well above where they were on May 2, when a 74-Bcf injection ended seven consecutive weeks of storage levels that were less than 1 trillion cubic feet (Tcf). This was the longest period of time that storage remained below 1 Tcf since 2003. Although strong injections have brought storage up considerably since then, working inventories remain at an 11-year low, presenting a challenge for storage operators during the 2014 injection season (April through October) of building sufficient inventories for the upcoming winter.

EIA forecasts that over the next five months, growth in U.S. natural gas production and flat electric power sector consumption will contribute to a record Lower 48 net injection from April through October of 2,587 Bcf. However, even if these record net injections take place, inventories for the 2014-15 winter season would still be at their lowest level since 2008. This is because of low starting inventories, following a 2013-14 winter defined by record high natural gas consumption and storage withdrawals, as waves of bitterly cold weather repeatedly swept across the United States.

natural gas average weekly supply demand 2014

Supply and demand values for each date are the average of that day, and the previous six days.

Natural gas markets in the United States began the winter season (November 2013 to March 2014) with a robust Lower 48 working gas inventory of 3,793 Bcf. Cold snaps starting in mid-November 2013 drove up demand for natural gas, particularly from residential and commercial consumers. Three consecutive months of 10-year record storage withdrawals (November 2013 through January 2014) pushed Lower 48 working inventories to their lowest January levels since 2004. Even after storage fell to a 10-year low, the cold snaps continued, pushing the Henry Hub spot price to $8.00 per million British thermal units (MMBtu) on some days in February. Sustained colder-than-normal temperatures through March pushed storage to its lowest level since 2003 and kept prices volatile, despite higher production.

Temperatures east of the Rockies were persistently cold, record-setting as much for their sustained nature as for any single event. This cold weather was particularly persistent in the Northeast, where there were 62 days during which temperatures were below freezing this winter, versus an average of 35 days for the previous five winters (2008-09 to 2012-13). Similar weather occurred in the Midwest, where there were 100 days below freezing this winter, versus 75 during the previous five winters, and the Midcontinent producing region, where there were 57 days below freezing this winter, versus an average of 38 days for the previous five winters.

weekly heating degree days of Pacific

weekly heating degree days of Mountain

weekly heating degree days of Midwest

weekly heating degree days of Northeast

Source: U.S. Energy Information Administration, based on data from the National Oceanic and Atmospheric Administration.

Bitterly cold waves swept through these three regions, as well as regions that traditionally have milder winter temperatures, like Texas, the Rockies, and the Pacific Northwest. This cold weather not only caused spikes in natural gas demand, but it also lessened the performance of the energy supply chain. Every major region of the contiguous United States experienced waves of significantly colder-than-normal temperatures:
A cold December in the Pacific Northwest contributed to natural gas spot prices there reaching a five-year average winter high.

  • On January 6, 2014, the temperature in Chicago dropped to -9 degrees Fahrenheit, 36 degrees below the average on that date from 2009 to 2013.
  • On this same day, temperatures in Houston dropped 22 degrees below the five-year average.
  • The next day, temperatures dropped in New Orleans, New York, and Philadelphia to 24 degrees, 25 degrees, and 29 degrees below their five-year averages, respectively.
  • On January 8, temperatures in Boston dropped to 18 degrees below their five-year average.
  • On February 6, temperatures in Seattle and Denver dropped to 21 degrees and 42 degrees below their five-year averages, respectively.
  • Temperatures on that date were also below average in California, whose independent system operator issued an alert requesting that customers reduce electricity consumption.

The cold weather had a dramatic effect on U.S. natural gas consumption, which rose to a record average of 91.0 billion cubic feet per day (Bcf/d) this winter. Consumption spiked during the cold weather in mid-December, early and late January, the beginning of February, and the beginning of March. U.S. natural gas consumption reached a same-month record every month from November 2013 to March 2014, according to EIA data going back to 1995. Cold weather drove consumption up by 9% over 2012-13 winter levels, with higher consumption occurring across all major sectors, despite higher prices.

Daily U.S. residential and commercial natural gas comsumption

Daily U.S. electric sector natural gas comsumption

Daily U.S. industrial sector natural gas comsumption

Source: U.S. Energy Information Administration, based on data from Bentek Energy LLC.

Total consumption

Total U.S. natural gas consumption surpassed the same-day maximum for the previous five winters (2008-09 to 2012-13) on 59 out of 151 days this winter, according to data from Bentek Energy LLC.
All of the top six total natural gas consumption days going back to January 1, 2005, took place this winter, as well as seven of the top 10. Three of these seven days were at the beginning of January (January 6, 7, and 8), three were in late January (January 22, 23, and 28), and one was in early February (February 6).
On January 7, total U.S. consumption reached an all-time record of 137.0 Bcf. This winter's spikes in total U.S. natural gas consumption were largely in response to weather-driven consumption from the residential and commercial sector. However, electric sector and industrial sector consumption also contributed to high levels of total consumption.
Residential/commercial sector consumption

Residential and commercial consumers increase their demand to a greater degree in response to colder temperatures than industrial and utility consumers, and were thus affected to a greater degree by this winter's cold snaps. The two highest residential/commercial consumption days occurred this winter (January 7 and January 28), as well as six of the top 10 dating back to January 1, 2005. 
On January 7, residential/commercial consumption reached a record 78.3 Bcf. Residential and commercial consumption rose by 15% over last winter, and accounted for approximately half of total U.S. winter consumption.
Natural gas consumption per residential household this winter averaged 66.0 million British thermal units (MMBtu), a 7% increase over both last winter's average and the average for the previous five winters. The largest increases in household consumption over last winter took place in the Midwest (10%), followed by the South (9%) and Northeast (8%).
Average household expenditures also increased in every U.S. Census region compared to last winter, but were generally close to the average for the past five winters. This was because the average delivered price of natural gas to U.S. households was 7% lower than the average for the previous five winters.
Electric power sector consumption
Although power sector natural gas consumption grew throughout most of the United States as cold temperatures led to increased electric demand for space heating, it decreased in the Northeast and Southeast, in response to higher prices. States in the Northeast increasingly relied on distillate fuel oil-fired electric generation when prices spiked. During a cold period in January, oil accounted for 25% of New England's total power generation, compared to 24% from natural gas. States in the Appalachian region and the Southeast region increasingly relied on coal-fired electric generation to meet higher power demand.
Electric power sector consumption rose on cold days and contributed to pushing total U.S. natural gas consumption to record-high levels this winter. However, the price sensitive nature of power sector demand, largely in the East, meant that this winter's daily power sector consumption record on January 7 of 31.2 Bcf ranked only 151st for all dates since January 1, 2005.
Industrial sector consumption

Industrial consumption of natural gas rose by 6% over last winter. It has risen every winter since 2008-09.
All of the nine days with the highest levels of industrial consumption since January 1, 2005, took place this winter. Cold temperatures contributed to spikes in industrial sector consumption, with all nine of the highest days occurring during the cold snaps at the beginning and end of January and in early February. As with the residential/commercial and electric power sectors, industrial sector consumption reached a record on January 7, of 23.8 Bcf. However, even on relatively warm days, industrial natural gas consumption this winter still reached same-day maximum levels when compared with the previous five winters.
Industrial natural gas consumption has fluctuated less in response to weather than consumption in the residential/commercial and electric generation sectors. It has reflected more of a structural increase in recent years. This is likely the result of higher demand in response to sustained economic growth since the recession of 2008-09, and the greater amounts of natural gas that increased production has made economically available to the manufacturing and bulk chemical industries.

Natural gas dry production rose this winter by 3%, or 2.2 Bcf/d, over the 2012-13 winter, to 68.0 Bcf/d, according to EIA data. This increase was significantly greater than last winter's 0.3 Bcf/d production increase. However, it was still well below the 7.5 Bcf/d rise in total U.S. consumption that took place this winter. Higher prices provided the incentive for greater levels of production. Greater levels of natural gas output in the Marcellus Shale contributed to the net increase in national production levels despite decreases in other basins. Higher production levels from the Eagle Ford in South Texas also contributed to this winter's increase in production. These gains exceeded production declines in plays containing relatively greater amounts of drier gas, such as the Haynesville Shale in Texas and Louisiana.

U.S. dry natural gas production from shale plays 2012 2013 2014

Source: U.S. Energy Information Administration calculations with data from Drillinginfo.

While total national production increased this winter, there were some daily decreases at many inland basins during periods of cold weather, including a 2.2 Bcf decrease on January 7, 2014, the eleventh largest daily decrease since January 1, 2005, according to Bentek data.

Net imports also rose this winter, by 0.7 Bcf/d over last winter's levels. Net imports from Canada into the United States increased, entirely in the Midwest and West, according to Bentek data. Net imports from Canada into the northeastern United States decreased slightly compared to last winter. Increased Marcellus production continued to reduced net inflows into the Northeast from other areas. However, net imports from Canada into the Northeast did spike during periods of high demand. Higher net imports from Canada drove up total U.S. net imports, despite a 0.3 Bcf/d decrease in net LNG imports and a slight increase in net U.S. natural gas pipeline exports to Mexico.

Natural gas markets in the United States began this winter season (November 2013 to March 2014) with relatively high levels of working gas inventories. Starting in mid-November 2013, however, U.S. natural gas consumption increased at a greater rate than supply, pushing inventories to their lowest levels since 2004, even as high prices curtailed electric sector demand in some parts of the country.

U.S. natural gas winter working inventories 1999- 2014

Source: U.S. Energy Information Administration, Natural Gas Monthly.

December saw record storage withdrawals in the West region, and a record 285-Bcf withdrawal in the Lower 48 states for the week ending on December 13, 2013. Lower 48 working gas inventories began January at 2,869 Bcf, and ended the month at less than 2,000 Bcf for the first time since 2005, following an overall record 967 Bcf monthly withdrawal. Heavy withdrawals continued through the first two weeks of February. Inventories, which had already reached their 10-year low by the end of January, dropped below 1,000 Bcf by the end of March for the first time since 2003. November-to-March withdrawals set records in all three storage regions, which depleted storage heading into April.

U.S. natural gas markets tightened as consumption outstripped supply and led to record-high storage withdrawals. The national benchmark spot price for natural gas traded at Henry Hub in Erath, Louisiana, averaged $4.63 per million British thermal units (MMBtu) during the 2013-14 winter, 33% higher than the winter of 2012-13, and the highest average winter spot price in four years, according to data from SNL Energy.

Daily Henry Hub spot prices

Source: U.S. Energy Information Administration, based on SNL Energy.

The Henry Hub spot price began last winter at less than $3.50/MMBtu, and increased to more than $5.00/MMBtu by the end of January, as inventories fell. As withdrawals continued to rise through the beginning of February, so did the Henry Hub spot price, peaking at $8.15/MMBtu on February 10, according to SNL data. Prices responded to sharp daily demand increases and continued drawdowns from storage by increasing significantly in the northeastern United States, as occurred last winter. However, these price spikes were not confined to the Northeast; they also occurred at trading hubs serving consumers in the central and western United States.

Natural gas spot prices in the eastern U.S. 

Natural gas spot prices in the central U.S. 
Natural gas spot prices in the western U.S. 
Source: U.S. Energy Information Administration, based on SNL Energy.

As occurred last winter, natural gas spot prices spiked in the northeastern United States.
At northeastern market hubs such as Algonquin Citygate in Boston and the Transco Zone 6-New York hub in New York City, natural gas pipeline constraints caused prices to spike during periods of high demand.
Low storage availability and a tighter supply-demand balance this past winter exacerbated this situation, with the price in New York City reaching a record $120/MMBtu during the southward shift of the polar vortex in late January. Prices also reached record levels in New England this winter.
Prices also rose significantly in the Mid-Atlantic region, where the Tetco-M3 (Pennsylvania) spot price rose in conjunction with price spikes farther north during late January's polar vortex incursion.
Despite significant increases in Marcellus supply, working gas inventories in Pennsylvania fell from 369 Bcf at the end of October 2013 to 65 Bcf by the end of March 2014, their lowest level since March 1996. West Virginia working inventories also fell, to their lowest level since March 2003.
Bitterly cold temperatures in the midwestern United States caused storage to drop significantly.
Illinois had record-low working gas inventories in January (116 Bcf), February (66 Bcf), and March (42 Bcf), compared to 253 Bcf of working gas at the end of October 2013. Working gas inventories in Michigan fell from 600 Bcf at the end of October 2013 to 56 Bcf at the end of March 2014, their lowest recorded end-March storage total. Working gas inventories in Texas, Louisiana, and Oklahoma also fell to their lowest levels since 2003.
As a result, when unusually cold weather hit the Midwest between the end of January and the end of February, the region had to rely on increasingly expensive gas transported north from the Gulf Coast on TransCanada's ANR Pipeline and Kinder Morgan's NGPL Pipeline, as well as Alberta production brought east on TransCanada's Canadian Mainline. This reliance on more expensive Gulf production and Canadian imports caused prices to spike significantly at the Chicago Citygate, by amounts above Henry Hub that had not been seen since at least 2005.
Inland areas farther to the southwest also saw price spikes, particularly in the Rockies, where a wave of cold weather caused prices to spike at the Opal and Cheyenne hubs in early February.
Increasingly expensive supply from Alberta, combined with bitterly cold temperatures, low storage, and drops in Rockies production on cold days, led to price spikes in the West.
The spot price from February through March surpassed $8/MMBtu at times at Niska's AECO Hub, located near the AECO storage facility in southeastern Alberta, a key trading point for western Canadian gas. This price was well above the $2/MMBtu prices at which gas traded at AECO as recently as September 2013.
Working gas inventories in California fell from 346 Bcf at the end of October to 94 Bcf by the end of March 2014, their lowest level for that month since 2003. Inventories in Washington also reached their lowest level since 2008, while inventories in Oregon fell to their lowest level since 2005.
As a result, prices spiked at PGE Citygate (California) and Northwest Sumas (Washington) when the West Coast was hit with a cold snap in early February. Prices also rose at Northwest Sumas when the Pacific Northwest was hit with cold weather in early December.

As Lower 48 working inventories continue to remain at an 11-year low, the focus has turned to the degree to which they rebuild in preparation for the upcoming 2014-15 winter season. Low inventories have contributed to keeping gas prices high. At the beginning of June, the Henry Hub spot price was more than $4.50/MMBtu, the first time that this occurred at this time of year since 2008. Higher prices have a number of implications for natural gas production, consumption, and storage this summer:

EIA projects that, partially in response to higher natural gas prices, dry production will average a record 69.3 Bcf/d from April through October 2014, 4% above the same period in 2013. Natural gas net imports will also rise by 4% over last year, to 3.5 Bcf/d from April through October.
EIA projects that natural gas power burn will increase by 1% compared to the 2013 injection season, to 24.1 Bcf/d, with April-October total consumption also increasing by 1%, to 60.8 Bcf/d.
Warmer weather is expected to increase the number of U.S. cooling degree days (CDDs) by 6% this injection season over last year, from 177 to 187 CDDs. Total U.S. power sector generation will increase by 1%, from an average of 10.8 million megawatthours per day to 11.0 million megawatthours per day.
However, largely because of higher natural gas prices, natural gas-fired power generation will remain flat compared to last year, while coal-fired power generation will increase by 3%. Coal-fired generation will continue to regain some of the power sector market share it lost in 2012, in keeping with a trend that began last summer.
As higher prices lead to higher natural gas production and net imports, and flat natural gas consumption from the power sector, EIA projects that record natural gas storage injections will take place through October, raising Lower 48 working gas in storage to 3,424 Bcf. However, because end-March inventories were so low following this winter's bitter cold, this would still be the lowest end-October storage level since 2008, presenting a challenge in terms of having enough gas in storage entering the 2014-15 winter withdrawal season.

Saturday, June 21, 2014

Fukushima energy cost for Japan

The 2014 Annual Report on Energy, published by the Ministry of Economy, Trade and Industry (METI), shows that Japan depended on imported fossil fuels for 88% of its electricity in fiscal year 2013, compared with 62% in fiscal 2010, the last full-year before the March 2011 accident at the Fukushima Daiichi plant. With almost its entire nuclear fleet offline, Japan reliance on fossil fuels peaked in fiscal year 2012 at 92.2%.
Japan was self-sufficient for just 6% of its energy demand in fiscal 2012, primarily from hydro and other renewable sources. With two units at the Ohi plant operating for just a few months, nuclear electricity generation met just 0.6% of its energy needs that year. Compared with fiscal 2010, prior to the Fukushima Daiichi accident, Japan was almost 20% energy self-sufficient, with nuclear energy meeting 15% of its total energy needs.
The additional fuel costs that Japan faced in fiscal 2013 to compensate for its nuclear reactors being idled was ¥3.6 trillion ($35.2 billion). Japan reported a trade deficit of ¥11.5 trillion ($112 billion) for the year, largely directly and indirectly due to these additional fuel costs. This compares with trade deficits of ¥6.9 trillion ($68 billion) in 2012 and ¥2.6 trillion ($25 billion) in 2011, following a ¥6.6 trillion ($65 billion) surplus in 2010.
In parallel, Japanese energy consumers have faced increasing electricity tariffs over the past three years. Domestic users have seen a 19.4% increase in tariffs between fiscal 2010 and fiscal 2013, while industrial users have seen their tariffs rise 28.4% over the same period.
Total electricity consumption in Japan decreased 8% between 2010 and 2012, from 996 TWh to 916 TWh. This decrease has mainly resulted from energy conservation measures.

As a results of its increased use of fossil fuels, Japan's carbon dioxide (CO2) emissions have also grown over the past three years. Emissions from electricity generation accounted for 36.2% of the country's total CO2 emissions of 1343 million tonnes in fiscal 2012, up from 33.6% of total emissions of 1307 million tonnes in 2011. In fiscal 2010, electricity generation accounted for just under 30% of Japan's total CO2 emissions of 1256 million tonnes.
An annual report on energy is published annually in Japan to provide an overview of the country's energy situation and to provide the government with guidance on energy policy. The report also provides a summary of measures taken to address the energy supply-demand balance by the government in fiscal 2013.
The policy has been three years in the making, and is Japan's fourth Basic Energy Plan - previous plans were passed in 2003, 2007 and 2010. It is the first to be approved since the Fukushima nuclear accident of 2011 prompted the extended shutdown of the nuclear power plants on which the country had hitherto relied for some 30% of its electricity. A draft of the plan was published by Japan's Ministry of Economy, Trade and Industry (METI) in February.
The latest plan, like its predecessors, recognises the necessity of energy security for the country which is poor in fossil fuel resources. The policy includes commitments to "clean energy" initiatives but places emphasis on ensuring stable and secure energy supplies.
Since its nuclear plants have been off line Japan has seen its fossil fuel imports and greenhouse gas emissions increase. Imports of LNG and thermal coal worth JPY 8.2 trillion ($80 billion) accounted for nearly 10% of total Japanese imports of JPY 81.3 trillion ($793 billion) in 2013.
Setting out policies for the production and supply of nuclear and other energy sources, including clean energy initiatives, the 78-page document designates nuclear energy as an important component of Japan's energy mix and looks to the restart of the country's reactors, while emphasising the priority of safety considerations in the restart and operation of any nuclear plants.
Nuclear power, according to METI, is a quasi-domestic source that gives stable power, operates inexpensively and has a low greenhouse gas profile. However, the ministry noted that nuclear must be developed with safety as a priority and with constant work on preparedness for emergency. Nuclear power is an 'important power source that supports the stability of the energy supply and demand structure' it said.
All of Japan's 48 operational nuclear reactors are currently off line pending clearance from the Nuclear Regulation Authority (NRA) under new regulations that came into force last July. To date, restart applications have been lodged for 17 of those reactors. The first reactors could restart later this year after completion of the NRA's review process.
Preliminary 2013 figures released by Japan's Ministry of Finance reveal a deficit of JPY 11.5 trillion ($112 billion), up 65% on 2012's deficit of 6.9 trillion ($67.5 billion). A major contributing factor has been the cost of the fossil fuels - especially liquefied natural gas (LNG) - that the country has been forced to continue to buy as the nuclear reactors that used to provide some 30% of Japan's electricity prior to the Fukushima accident of 2011 remain offline.
Imports of LNG, at 87.5 million tonnes, were 0.2% up on 2012 figures, but a weak yen meant that the value of the imports, at JPY 7.1 trillion ($69 billion), was 17.5% up on 2012. Imports of coal for use in thermal power stations were also up on 2012 figures. In total, imports of LNG and thermal coal worth JPY 8.2 trillion ($80 billion) accounted for nearly 10% of total Japanese imports of JPY 81.3 trillion ($793 billion) for the year. Total exports of JPY 69.8 trillion ($681 billion), while 9.5% up on 2012, were not sufficient to avoid the overall deficit.
Japan's entire fleet of nuclear reactors currently remains out of service pending restart approvals under a new regulatory regime introduced last year by the country's Nuclear Regulation Authority (NRA). So far 16 reactors have applied for permission to restart, although none has yet completed the NRA's rigorous new approvals procedure.

The three-year rally in liquefied natural gas is cooling as Asia-Pacific supplies jump and demand slows from Japanese utilities preparing to restart nuclear reactors.
LNG shipped to northeast Asia next winter may be sold at the lowest price since 2012 for that time of year, when demand typically peaks, according to a Bloomberg News survey of traders and analysts. Exxon Mobil Corp. and BG Group Plc are bringing new supplies to Asia this year before at least four projects start in 2015, including the first U.S. exports.
Prices have doubled over the past three years since the Fukushima disaster in March 2011, as utilities turned to fossil fuels such as LNG to compensate for the loss of the atomic plants. Japan is preparing to restart at least two of 48 nuclear reactors that were shut in the wake of an earthquake and tsunami that hit the country.
“We have quite a lot of new supply capacity coming on,” Tony Regan, an energy consultant at Tri-Zen International Inc. in Singapore who predicts LNG prices may be at $17 per million British thermal units in the first quarter of 2015, said by phone this month. “There are a number of things that will moderate the upward potential of prices this winter. The regular one is nukes.”
Supplies may cost $18 per million Btu in the first quarter of 2015, the median estimate of 13 traders and analysts in the Bloomberg survey shows. That’s 9 percent lower than a record $19.70 in February, according to data from Energy Intelligence Group in New York. The fuel has averaged $16.18 this year, compared with $16.51 in 2013.
Exxon started sending cargoes to Asia from its $19 billion Papua New Guinea project last month, while BG Group is due to begin exporting from its Queensland Curtis plant in Australia at the end of 2014. Santos Ltd., Chevron Corp. and Houston-based Cheniere Energy Inc. (LNG) are among producers scheduled to start shipping LNG from new operations next year.
Global gas exports are forecast to increase by 18 million metric tons, or 7.5 percent, to 257 million tons in 2015, Energy Aspects Ltd., an industry consultant based in London, said in a report on May 28. The increase would be enough to meet China’s LNG requirements for a year.
Imports to Japan, the biggest buyer of LNG and once Asia’s largest nuclear-power producer, may rise 1.4 percent in 2014 before falling by 1.28 million tons next year as the nuclear plants restart, according to Energy Aspects.
LNG sold into Japan averaged $7.64 per million Btu in 2010, the year before the earthquake and meltdown of Tokyo Electric Power Co.’s Fukushima Dai-Ichi plant, according to estimates from Tri-Zen International. Forecasts in the Bloomberg survey ranged from $16.50 to $19.50 for the 2015 first-quarter high.
Delays to restarts in Japan, which is facing public opposition to atomic power, may boost LNG demand. Two units may resume this year, Cantor Fitzgerald LP said in a June 12 report. This compares with a January forecast for 12 to start.
Japan has been without atomic power since September, when the last of its 48 reactors shut for checks. Utilities including Tokyo Electric, the country’s biggest, have applied for the Nuclear Regulation Authority’s safety review of 19 units, according to the regulator’s website.
“The underlying market tightness will cause average Asia spot prices for 2014 to remain robust,” Andrew Walker, the vice president of global LNG at BG in Reading, U.K., said by e-mail on June 11. The early start of Exxon’s Papua New Guinea project, some buyers holding high inventories and the weather outlook in key markets have caused prices to slip recently, he said.
LNG into northeast Asia has dropped to $11.95 a million Btu in the week ended June 16, the lowest since April 2011, amid “continued weak buying interest and a comfortable supply outlook,” according to the Energy Intelligence Group’s World Gas Intelligence publication. Prices may decline next week on more spot cargoes in the market, four of six traders said in a Bloomberg survey that ended today.
Japan, the world’s third-biggest economy, imported a record 87.49 million tons of LNG last year. The country may reduce consumption of the fuel this year as nuclear production resumes, Yoshihiko Sakanashi, the executive vice president of Electric Power Development, or J-Power, said in an interview on June 1.
The average price of spot LNG cargoes imported by Japan in May was $14.80, down from $16 a month earlier, the Ministry of Economy, Trade and Industry said in a report today.
The restart of the reactors in Japan “will change the mood of the market,” Hiroki Sato, the general manager of Chubu Electric Power Co.’s fuels department in Nagoya, said in a June 12 interview. “Spot prices will be stable at current levels in coming months and rise somewhat, but not to levels close to those of last year during the winter-demand season.”
Asia’s LNG buyers, accounting for about three-quarters of global consumption in 2013, are also considering North American supplies after a surge in extraction from shale deposits.
Cheniere Energy’s Sabine Pass terminal in Louisiana, scheduled to start producing LNG by the end of next year, is the first to win full approval for U.S. exports from the Federal Energy Regulatory Commission since ConocoPhillips’s Alaskan Kenai plant in 1967.
Sempra Energy (SRE) won final U.S. approval yesterday from the FERC to build its Cameron export terminal. The project in Louisiana will start operations in 2018, according to the San Diego-based company’s website.
In addition to LNG from Australia and the U.S., Mozambique and Russia will add to supplies in the global market, Osamu Fujisawa, a Tokyo-based independent energy economist who has worked for Royal Dutch Shell Plc and Saudi Arabian Oil Co., said June 17 by phone. “So there will be a lot of supply, and this will not be good for spot LNG prices.”

Wednesday, June 11, 2014

UK natural gas prices rose from year lows in June

British day-ahead wholesale gas prices rose 2.9 percent on Wednesday on undersupply forecasts, a drop in LNG availability from import terminals, and the risk that EU-brokered talks between Ukraine and Russia over a pricing dispute will drag on.
The prompt contract gained 1.1 pence to a four-day high of 38.65 pence/therm, climbing back from a near four-year low of 36.25 pence hit on Monday due to low demand and healthy supply.
British gas demand was forecast to be around 205 million cubic metres (mcm) on Wednesday, some 28 mcm above predicted supply, according to the National Grid .
Nominated sendout from Britain's liquefied natural gas (LNG) terminals was estimated to fall to 44 mcm from 50 mcm on Tuesday, which analysts at Thomson Reuters Point Carbon said could be to offset a rise in supply caused by the closure of an export pipeline.
The InterconnectorUK (IUK) pipeline, which sends gas to continental Europe, was taken offline on Wednesday for maintenance that is expected to last until June 26, meaning more supply availability.
"LNG could be one of the supply source that will adjust down following the cut in IUK exports. We have therefore reduced our LNG sendout forecast over the next 15 days," the analysts said.
Three LNG cargoes carrying a total 444 mcm are also due to arrive in Britain over the next week, helping to increase supply and boost storage injections.
Meanwhile, Russia and Ukraine will resume efforts to resolve a gas pricing dispute on Wednesday after a Russian deadline for Kiev to pay some of its debts passed without Moscow cutting off supplies.
"If no solution is found over the day, gas prices could go up," the Point Carbon analysts said.
Russia's Gazprom has moved a deadline for Ukraine to start paying in advance for gas to June 16, the Kremlin controlled company's chief executive said.
Ukrainian Prime Minister Arseny Yatseniuk said his country had rejected a proposal by Moscow for what would amount to a reduction of $100 per cubic metre in the price Kiev pays for Russian gas.
A Gazprom spokesman said Russian gas supplies to the European Union remained stable.
British gas prices further down the forward curve also increased, with the within-day contract adding 4 percent to 38.75 pence/therm.
Gas imports from Norway via the Langeled pipeline were healthy but expected to drop from June 15, when compressor maintenance at the country's Troll gas is due to start.
"We believe the combination of that maintenance with the maintenance that started at (Norway's Kollsnes gas processing plant) on June 7 should slightly impact Langeled flows downward," the Point Carbon analysts said.
Temperatures across Britain are expected to remain above seasonal norms over most of the next two weeks.
British day-ahead baseload power also rose, gaining 80 pence to 37.70 pounds per megawatt-hour.